Method and System for Fracturing a Formation

ABSTRACT

Systems and methods are described for fracturing a production formation. A method includes drilling a well into a zone proximate to a production formation, and increasing a volume of the zone through the well in order to apply a mechanical stress to the production formation.

CROSS-REFERENCE TO RELATED APPLICATION

This application claims the benefit of U.S. Provisional PatentApplication No. 61/407,249 filed Oct. 27, 2010 entitled METHOD ANDSYSTEM FOR FRACTURE STIMULATION, and also claims benefit to U.S.Provisional Application No. 61/544,757, filed Oct. 7, 2011, entitledMETHOD AND SYSTEM FOR FRACTURE STIMULATION BY CYCLIC FORMATION SETTLINGAND DISPLACEMENT and U.S. Provisional Application No. 61/544,766, filedOct. 7, 2011 entitled METHOD AND SYSTEM FOR FRACTURE STIMULATION BYFORMATION DISPLACEMENT.

FIELD OF THE INVENTION

Embodiments of the present techniques relate to a method and system forfracture stimulation of subterranean formations to enhance the recoveryof hydrocarbons. Specifically, an exemplary embodiment provides forcreating fractures and other flow paths by delamination and rubblizationof formations.

BACKGROUND

This section is intended to introduce various aspects of the art thatmay be topically associated with embodiments of the present techniques.This discussion is believed to assist in providing a framework tofacilitate a better understanding of particular aspects of the presenttechniques. Accordingly, it should be understood that this sectionshould be read in this light, and not necessarily as admissions of priorart.

As hydrocarbon reservoirs that are easily harvested, such as reservoirson land or reservoirs located in shallow ocean water, are used up, otherhydrocarbon sources must be used to keep up with energy demands. Suchreservoirs may include any number of unconventional hydrocarbon sources,such as biomass, deep-water oil reservoirs, and natural gas from othersources.

One such unconventional hydrocarbon source is natural gas produced fromformations that form unconventional gas reservoirs, including, forexample, shale and coal seams. Because unconventional gas reservoirs mayhave insufficient permeability to allow significant fluid flow to awellbore, many of such unconventional gas reservoirs are currently notconsidered as practical sources of natural gas. However, natural gas hasbeen produced for years from low permeability reservoirs having naturalfractures. Furthermore, a significant increase in shale gas productionhas resulted from hydraulic fracturing, which can be used to createextensive artificial fractures around wellbores. When combined withhorizontal drilling, which is often used with wells in tight gasreservoirs, the hydraulic fracturing may allow formerly unpracticalreservoirs to be commercially viable.

The fracturing process is complicated and often requires numeroushydraulic fractures in a single well and numerous wells for an economicfield development. More efficient fracturing processes may provide amore productive reservoir. In other words, a greater amount of the gas,or other hydrocarbon, trapped in a relatively non-porous reservoir, suchas a tight gas, tight sand, shale layer or even a coal seam may beharvested. Accordingly, numerous researchers have explored ways toimprove fracturing.

For example, U.S. Pat. No. 3,455,391, to Matthews, et al., discloses aprocess for horizontally fracturing subterranean earth formations. Theprocess is performed by injecting a hot fluid at high pressure, untilvertical fractures are formed and then closed due to thermal expansionof the earth formation. A fluid is then injected at a pressuresufficient to form horizontal fractures.

A similar process is disclosed in U.S. Pat. No. 3,613,785, to Closmanand Phocas. In this process a wellbore is extended into the formationand a vertical fracture is generated by pressurizing the borehole. A hotfluid is injected into the formation to heat the formation, untilthermal stressing of the formation matrix material causes the horizontalcompressive stress in the formation to exceed the vertical compressivestress at a location selected for a second well. Hydraulicallyfracturing the formation through this second well can form a horizontalfracture extending into the formation.

Other approaches have focused on relieving stress in the formation, forexample, by cavitation of the formation. For example, U.S. Pat. No.5,147,111, to Montgomery, discloses a method for cavity inducedstimulation of coal degasification wells. The method can be used forimproving the initial production of fluids, such as methane, from a coalseam. To perform the method, a well is drilled and completed into theseam. A tubing string is run into the hole and liquid carbon dioxide ispumped down the tubing while a backpressure is maintained on the wellannulus. The pumping is stopped, and the pressure is allowed to builduntil it reached a desired elevated pressure, for example, 1500 to 2000psia. The pressure is quickly released, causing the coal to fail andfragment into particles. The particles are removed to form a cavity inthe seam. The cavity can allow expansion of the coal, potentiallyleading to opening of cleats within the coal seam.

A similar concept has been described in Ukraine Patent No. 35282, whichdiscloses another method for coal degasification, but through subsurfacegasification of an underburden coal seam (a coal seam that underlies thegas-containing formation). In this process, wellbores are drilledthrough an underburden coal bed so that a gasification catalyst can beapplied. Once gasification occurs and lowers the underburden pressuredue to depletion, subsidence of the overburden (e.g., the layercontaining the gas) occurs due to gravitational loading. The subsidencecan potentially create microfractures within the overburden reservoir,thereby allowing improved gas migration to the degassing wells.

It has also been noted that vertical wells and mining processes canlower stress points on coal seams, leading to increases in theproduction of coal bed methane. For example, S. Sang, et al., “Stressrelief coalbed methane drainage by surface vertical wells in China,”International Journal of Coal Geology, Volume 82, 196-203 (2010),presents a summary of studies on improved coalbed methane production bystress relief. The paper summarizes the status of engineering practice,technology, and research related to stress relief coalbed methane (CBM)drainage using surface wells in China during the past 10 years. Commentsare provided on the theory and technical progress of this method. Inhigh gas mining areas, such as the Huainan, Huaibei and Tiefa miningareas, characterized by heavily sheared coals with relatively lowpermeability, stress relief CBM surface well drainage has beensuccessfully implemented and has broad acceptance as a CBM exploitationtechnology. The fundamental theories underpinning stress relief CBMsurface well drainage include elements relating to: (1) formation layerdeformation theory, vertical zoning and horizontal partitioning, and thechange in the stress condition in mining stopes; (2) a theory regardingan Abscission Circle in the development of mining horizontal abscissionfracture and vertical broken fracture in overlaying formations; and (3)the theory of stress relief inducing permeability increase in protectedcoal seams during mining; and the gas migration-accumulation theory ofstress relief CBM surface well drainage.

Other techniques for increasing production from coal beds, and otherreservoirs, have focused on in-situ pyrolysis of hydrocarbons in areservoir, followed by production of hydrocarbons from the reservoir.All of these techniques above have focused on the treatment of thehydrocarbon reservoir itself. Further, some techniques have taught thatrelieving a stress on a reservoir may enhance the production ofhydrocarbons, for example, by allowing cleats to open up in coal seams.

Related information may be found in S. E. Laubach, et al.,“Characteristics and origins of coal cleat: A review,” InternationalJournal of Coal Geology 35 (1998), 175-207; Ian Palmer, “Coalbed methanecompletions: A world view,” International Journal of Coal Geology 82(2010), 184-195; Jack A. Pashin, “Stratigraphy and structure of coalbedmethane reservoirs in the United States: An overview,” InternationalJournal of Coal Geology 35 (1998), 209-240; Pablo F. Sanz, et al.,“Mechanical models of fracture reactivation and slip on bedding surfacesduring folding of the asymmetric anticline at Sheep Mountain, Wyoming,”Journal of Structural Geology 30 (2008), 1177-1191; V. Palchik,“Localization of mining-induced horizontal fractures along formationlayer interfaces in overburden: field measurements and prediction,”Environ. Geol. 48 (2005), 68-80; and Stephen P. Laubach, et al.,“Differential compaction of interbedded sandstone and coal,” from:Cosgrove, J. W. and Ameen, M. S. (eds.), Forced Folds and Fractures,Geological Society of London, Special Publications, 169, 51-60 (TheGeological Society of London 2000).

SUMMARY

An embodiment described herein provides a method for fracturing aproduction formation. The method includes drilling a well into a zoneproximate to a production formation, and increasing a volume of the zonethrough the well in order to apply a mechanical stress to the productionformation.

Another embodiment described herein provides a hydrocarbon productionsystem. The system includes a hydrocarbon reservoir and a zone proximateto the hydrocarbon reservoir. The system also includes a stimulationwell drilled to the zone and a stimulation system configured to create avolumetric change in the zone through the stimulation well. A productionwell in the system is drilled to the hydrocarbon reservoir.

Another embodiment described herein provides a method for harvestinghydrocarbons from a formation. The method includes drilling a productionwell in a production interval and drilling a stimulation well in atreatment interval. A volumetric change is caused in the treatmentinterval through the stimulation well, wherein the volumetric changecauses the formation of a fracture field in the production interval. Theproduction well is completed to place the production well in contactwith the fracture field and hydrocarbons are harvested from theproduction interval

BRIEF DESCRIPTION OF THE DRAWINGS

The advantages of the present techniques are better understood byreferring to the following detailed description and the attacheddrawings, in which:

FIG. 1 is a diagram of a hydraulic fracturing process;

FIG. 2 is a drawing of a local stress state for an element in ahydrocarbon bearing subterranean formation;

FIG. 3 is a drawing of a first mode (mode 1) of fracture formation,commonly resulting from a standard hydraulic fracturing process;

FIG. 4 is an exemplified drawing of a well treatment system such as ahydraulic fracturing system, wherein a zone below a hydrocarbon bearingsubterranean formation is subjected to a volumetric expansion, which canplace stress on the hydrocarbon bearing subterranean formation leadingto fracturing;

FIG. 5 is a block diagram of a method for stimulation of a hydrocarbonbearing subterranean formation by treating a formation outside of thereservoir;

FIG. 6 is a more detailed schematic view of a delamination fracturestimulation showing the physics that may lead to delaminationfracturing;

FIG. 7 is a drawing of two modes of sliding fracture formation that mayparticipate in delamination fracture stimulation as discussed herein;

FIG. 8 is a drawing of rubblization during shearing at a fractureinterface or boundary;

FIG. 9 is a drawing of an azimuthal rotation of fracture planes within aformation that may occur as a result of cyclic treatment of theformation;

FIG. 10 is a drawing of a vertical well passing through a reservoirinterval and a treatment interval, in which a notch has been formed inthe treatment interval;

FIG. 11 is a drawing of the stress distribution in the formation aroundthe tip of a notch;

FIGS. 12(A)-(D) are drawings of a number of well configurations that canbe used in embodiments of the techniques described herein;

FIGS. 13(A)-(F) are drawings of a series of branched wells that can usethe configurations discussed with respect to FIGS. 12(B) and (D); and

FIG. 14 is a drawing of a stacked treatments technique that may beuseful for increasing the effects of the treatment of a zone on thehydrocarbon bearing subterranean formation.

DETAILED DESCRIPTION

In the following detailed description section, the specific embodimentsof the present techniques are described in connection with exemplaryembodiments. However, to the extent that the following description isspecific to a particular embodiment or a particular use of the presenttechniques, this is intended to be for exemplary purposes only andsimply provides a description of the exemplary embodiments. Accordingly,the present techniques are not limited to the specific embodimentsdescribed below, but rather, such techniques include all alternatives,modifications, and equivalents falling within the true spirit and scopeof the appended claims.

At the outset, and for ease of reference, certain terms used in thisapplication and their meanings as used in this context are set forth. Tothe extent a term used herein is not defined below, it should be giventhe broadest definition persons in the pertinent art have given thatterm as reflected in at least one printed publication or issued patent.Further, the present techniques are not limited by the usage of theterms shown below, as all equivalents, synonyms, new developments, andterms or techniques that serve the same or a similar purpose areconsidered to be within the scope of the present claims.

The “Bulk modulus” of a rock sample from a formation relates thepressure to the volume change given by the dilation _(kk). It is anelastic property of the material and is usually denoted by the Englishalphabet K having units the same as that of stress, and is given by:

$K = {\frac{{3\lambda} + {2\mu}}{3}.}$

“Cavitation completion” or “cavitation” is a process by which an openingmay be made in a formation. Generally, cavitation is performed bydrilling a well into a formation. The formation is then pressurized inthe vicinity of the well. The pressure is suddenly released, causing thematerial in the vicinity of the well to fragment. The fragments anddebris may then be swept to the surface through the well by circulatinga fluid through the well.

“Cleat system” is the system of naturally occurring joints that arecreated as a coal seam forms over geologic time. A cleat system allowsfor the production of natural gas if the provided permeability to thecoal seam is sufficient.

“Coal” is a solid hydrocarbon, including, but not limited to, lignite,sub-bituminous, bituminous, anthracite, peat, and the like. The coal maybe of any grade or rank. This can include, but is not limited to, lowgrade, high sulfur coal that is not suitable for use in coal-fired powergenerators due to the production of emissions having high sulfurcontent.

“Coalbed methane” (CBM) is a natural gas that is adsorbed onto thesurface of coal. CBM may be substantially comprised of methane, but mayalso include ethane, propane, and other hydrocarbons. Further, CBM mayinclude some amount of other gases, such as carbon dioxide (CO₂) andnitrogen (N₂).

A “compressor” is a machine that increases the pressure of a gas by theapplication of work (compression). Accordingly, a low pressure gas (forexample, 5 psig) may be compressed into a high-pressure gas (forexample, 1000 psig) for transmission through a pipeline, injection intoa well, or other processes.

“Directional drilling” is the intentional deviation of the wellbore fromthe path it would naturally take. In other words, directional drillingis the steering of the drill string so that it travels in a desireddirection. Directional drilling can be used for increasing the drainageof a particular well, for example, by forming deviated branch bores froma primary borehole. Directional drilling is also useful in the marineenvironment where a single offshore production platform can reachseveral hydrocarbon bearing subterranean formations or reservoirs byutilizing a plurality of deviated wells that can extend in any directionfrom the drilling platform. Directional drilling also enables horizontaldrilling through a reservoir to form a horizontal wellbore. As usedherein, “horizontal wellbore” represents the portion of a wellbore in asubterranean zone to be completed which is substantially horizontal orat an angle from vertical in the range of from about 15° to about 75°. Ahorizontal wellbore may have a longer section of the wellbore traversingthe payzone of a reservoir, thereby permitting increases in theproduction rate from the well.

“Exemplary” is used exclusively herein to mean “serving as an example,instance, or illustration.” Any embodiment described herein as exemplaryis not to be construed as preferred or advantageous over otherembodiments.

A “facility” is tangible piece of physical equipment, or group ofequipment units, through which hydrocarbon fluids are either producedfrom a reservoir or injected into a reservoir. In its broadest sense,the term facility is applied to any equipment that may be present alongthe flow path between a reservoir and its delivery outlets, which arethe locations at which hydrocarbon fluids either leave the model(produced fluids) or enter the model (injected fluids). Facilities maycomprise production wells, injection wells, well tubulars, wellheadequipment, gathering lines, manifolds, pumps, compressors, separators,surface flow lines, and delivery outlets. In some instances, the term“surface facility” is used to distinguish those facilities other thanwells.

As used herein, the force “f” could be compressional, leading tolongitudinally compressing the strength member, or tensional, leading tolongitudinally extending the strength member. In the case of a strengthmember in a seismic section, the force will typically be tension.

“Formation” refers to a body or section of geologic strata, structure,formation, or other subsurface solids or collected material that issufficiently distinctive and continuous with respect to other geologicstrata or other characteristics that it can be mapped, for example, byseismic techniques. A formation can be a body of geologic strata ofpredominantly one type of rock or a combination of types of rock, or afraction of strata having substantially common set of characteristics. Aformation can contain one or more hydrocarbon-bearing subterraneanformations. Note that the terms formation, hydrocarbon bearingsubterranean formation, reservoir, and interval may be usedinterchangeably, but may generally be used to denote progressivelysmaller subsurface regions, zones, or volumes. More specifically, ageologic formation may generally be the largest subsurface region, ahydrocarbon reservoir or subterranean formation may generally be aregion within the geologic formation and may generally be ahydrocarbon-bearing zone, a formation, reservoir, or interval havingoil, gas, heavy oil, and any combination thereof. An interval orproduction interval may generally refer to a sub-region or portion of areservoir. A hydrocarbon-bearing zone, or production formation, may beseparated from other hydrocarbon-bearing zones by zones of lowerpermeability such as mudstones, shales, or shale-like (highly compacted)sands. In one or more embodiments, a hydrocarbon-bearing zone mayinclude heavy oil in addition to sand, clay, or other porous solids.

A “fracture” is a crack, delamination, surface breakage, separation,crushing, rubblization, or other destruction within a geologic formationor fraction of formation that is not related to foliation or cleavage inmetamorphic formation, along which there has been displacement ormovement relative to an adjacent portion of the formation. A fracturealong which there has been lateral displacement may be termed a fault.When walls of a fracture have moved only normal to each other, thefracture may be termed a joint. Fractures may enhance permeability ofrocks greatly by connecting pores together, and for that reason, jointsand faults may be induced mechanically in some reservoirs in order toincrease fluid flow.

“Fracturing” refers to the structural degradation of a treatmentinterval, such as a subsurface shale formation, from applied thermal ormechanical stress. Such structural degradation generally enhances thepermeability of the treatment interval to fluids and increases theaccessibility of the hydrocarbon component to such fluids. Fracturingmay also be performed by degrading rocks in treatment intervals bychemical means. “Fracture network” refers to a field or network ofinterconnecting fractures, usually formed during hydraulic fracturing. A“fracture field” is a group of fractures, which may or may not beinterconnected, and are created by a single fracturing event, such as bya volumetric change in a zone proximate to a target formation, whichfractures the target formation.

“Fracture gradient” refers to an equivalent fluid pressure sufficient tocreate or enhance one or more fractures in the subterranean formation.As used herein, the “fracture gradient” of a layered formation alsoencompasses a parting fluid pressure sufficient to separate one or moreadjacent bedding planes in a layered formation. It should be understoodthat a person of ordinary skill in the art could perform a simpleleak-off test on a core sample of a formation to determine the fracturegradient of a particular formation.

“Geomechanical stress” or “stress” including a change related thereto,or similar phrase, refers generally to the forces external to orinterior to a formation acting upon or within such formation. The forcesmay define a stress state, condition, or property of a formation, zone,or other geologic strata, and/or any fluid contained therein. Inembodiments, the stress state may be manipulated to control the creationof fractures in particular directions.

“Heat source” is any system for providing heat to at least a portion ofa formation substantially by conductive or radiative heat transfer. Forexample, a heat source may include electric heaters such as an insulatedconductor, an elongated member, or a conductor disposed in a conduit.Other heating systems may include electric resistive heaters placed inwells, electrical induction heaters placed in wells, circulation of hotfluids through wells, resistively heated conductive propped fracturesemanating from wells, downhole burners, exothermic chemical reactions,and in situ combustion. A heat source may also include systems thatgenerate heat by burning a fuel external to or in a formation. Thesystems may be surface burners, downhole gas burners, flamelessdistributed combustors, and natural gas distributed combustors. In someembodiments, heat provided to or generated in one or more heat sourcesmay be supplied by other sources of energy. The other sources of energymay directly heat a formation, or the energy may be applied to atransfer medium that directly or indirectly heats the formation. Forexample, an “electrofrac heater” may use electrical conductive proppedfractures to apply heat to the formation. In an electrofrac heater, aformation is hydraulically fractured and a graphite proppant is used toprop the fractures open. An electric current may then be passed throughthe graphite proppant causing it to generate heat, which heats thesurrounding formation.

“Hydraulic fracturing” is used to create single or branching fracturesthat extend from the wellbore into reservoir formations so as tostimulate the potential for production. A fracturing fluid, typically aviscous fluid, is injected into the formation with sufficient pressureto create and extend a fracture, and a proppant is used to “prop” orhold open the created fracture after the hydraulic pressure used togenerate the fracture has been released. When pumping of the treatmentfluid is finished, the fracture “closes.” Loss of fluid to a permeableformation results in a reduction in fracture width until the proppantsupports the fracture faces. The fracture may be artificially held openby injection of a proppant material. Hydraulic fractures may besubstantially horizontal in orientation, substantially vertical inorientation, or oriented along any other plane. Generally, the fracturestend to be vertical at greater depths, due to the increased magnitude ofthe vertical stress relative to the horizontal stresses. As used herein,fracturing may take place in portions of a formation outside of ahydrocarbon bearing subterranean formation in order to enhancehydrocarbon production from the hydrocarbon bearing subterraneanformation.

“Hydrocarbon production” refers to any activity associated withextracting hydrocarbons from a well or other opening. Hydrocarbonproduction normally refers to any activity conducted in or on the wellafter the well is completed. Accordingly, hydrocarbon production orextraction includes not only primary hydrocarbon extraction but alsosecondary and tertiary production techniques, such as injection of gasor liquid for increasing drive pressure, mobilizing the hydrocarbon ortreating by, for example chemicals or hydraulic fracturing the wellboreto promote increased flow, well servicing, well logging, and other welland wellbore treatments.

“Hydrocarbons” are generally defined as molecules formed primarily ofcarbon and hydrogen atoms such as oil and natural gas. Hydrocarbons mayalso include other elements, such as, but not limited to, halogens,metallic elements, nitrogen, oxygen, and/or sulfur. Hydrocarbons may beproduced from hydrocarbon bearing subterranean formations through wellspenetrating a hydrocarbon containing formation. Hydrocarbons derivedfrom a hydrocarbon bearing subterranean formation may include, but arenot limited to, kerogen, bitumen, pyrobitumen, asphaltenes, oils,natural gas, or combinations thereof. Hydrocarbons may be located withinor adjacent to mineral matrices within the earth. Matrices may include,but are not limited to, sedimentary rock, sands, silicilytes,carbonates, diatomites, and other porous media.

A “hydraulic fracture” is a fracture at least partially propagated intoa formation, wherein the fracture is created through injection ofpressurized fluids into the formation. While the term “hydraulicfracture” is used, the techniques described herein are not limited touse in hydraulic fractures. The techniques may be suitable for use inany fractures created in any manner considered suitable by one skilledin the art. Hydraulic fractures may be substantially horizontal inorientation, substantially vertical in orientation, or oriented alongany other plane. Generally, the fractures tend to be vertical at greaterdepths, due to the increased magnitude of the vertical stress relativeto the horizontal stresses.

“Ideally elastic” refers to a material in which a body formed of thematerial recovers its original form completely upon removal of theforces causing the deformation, and a material that has a one-to-one,i.e., unique relationship between the state of stress and the state ofstrain at a given temperature. For many materials, strain is directlyproportional to the stress, at least at stresses below the yieldstrength of a material, This linear relationship between strain _(u) andstress _(u) occurring at stresses below the yield strength is known asthe generalized Hooke's law, and is represented by the formula:

σ_(ij) =C _(ijkl)ε_(kl)

where summation convention is employed, meaning that in Cartesiancoordinates whenever the same letter subscript occurs twice in a term,that subscript is to be given all possible values and the results addedtogether, and here i, j, k, l each take the values 1, 2, 3. The 9equations represented above contain 81 elastic constants, C_(ijkl), butsymmetry of the stress tensor, _(ij), and existence of a strain energyfunction reduce the number of distinct constants to 21. A “plane ofelastic symmetry” is a plane in which the elastic constants at a pointhave the same values for every pair of coordinate systems which aremirror images of each other in a certain plane.

“Imbibition” refers to the incorporation of a fracturing fluid into afracture face by capillary action. Imbibition may result in decreases inpermeation of a formation fluid across the fracture face, and is knownto be a form of formation damage. For example, if the fracturing fluidis an aqueous fluid, imbibition may result in lower transport of organicmaterials, such as hydrocarbons, across the fracture face, resulting indecreased recovery. The decrease in hydrocarbon transport may outweighany increases in fracture surface area resulting in no net increase inrecovery, or even a decrease in recovery, after fracturing.

“In-Situ” or “insitu” refers to a state, condition, or property of ageologic formation, strata, zone, and/or fluids therein, prior tochanging or altering such state, condition, or property by an actionaffecting the formation and/or fluids therein. Changes to the insituproperties may be effected by substantially any action upon theformation, such as producing or removing fluids from a formation,injecting or introducing fluids or other materials into a formation,stimulating a formation, causing a collapse such as permitting awellbore collapse or dissolving supporting strata, removing adjacentformation or fluid, heating or cooling the formation, or other actionthat effects change in the state, condition or property of theformation. The insitu state may or may not be the virgin or originalstate of the formation, but is a relative term that may in fact merelyreference a state that exists prior to undertaking some action upon theformation.

An “isotropic” material is one in which the body's elastic constants,C_(ijkl), are the same in every set of reference axes at any point for agiven situation. For a such a material, the number of distinct elasticconstants is two, and the strains can be related to the stresses byHooke's Law:

σ_(ij)=λδ_(ij)ε_(kk)+2με_(ij),

where the distinct elastic constants are and, the Lamé constants. isalso known as the “modulus of rigidity” or “shear modulus” and issometimes expressed as G. Three additional constants, E, K, and can bedefined as combinations of the Lame constants.

As used herein, “material properties” represents any number of physicalconstants that reflect the behavior of a rock. Such material propertiesmay include, for example, Young's modulus (E), Poisson's Ratio ( ),tensile strength, compressive strength, shear strength, creep behavior,and other properties. The material properties may be measured by anycombinations of tests, including, among others, a “Standard Test Methodfor Unconfined Compressive Strength of Intact Rock Core Specimens,” ASTMD 2938-95; a “Standard Test Method for Splitting Tensile Strength ofIntact Rock Core Specimens [Brazilian Method],” ASTM D 3967-95aReapproved 1992; a “Standard Test Method for Determination of the PointLoad Strength Index of Rock,” ASTM D 5731-95; “Standard Practices forPreparing Rock Core Specimens and Determining Dimensional and ShapeTolerances,” ASTM D 4435-01; “Standard Test Method for Elastic Moduli ofIntact Rock Core Specimens in Uniaxial Compression,” ASTM D 3148-02;“Standard Test Method for Triaxial Compressive Strength of UndrainedRock Core Specimens Without Pore Pressure Measurements,” ASTM D 2664-04;“Standard Test Method for Creep of Cylindrical Soft Rock Specimens inUniaxial Compressions,” ASTM D 4405-84, Reapproved 1989; “Standard TestMethod for Performing Laboratory Direct Shear Strength Tests of RockSpecimens Under Constant Normal Stress,” ASTM D 5607-95; “Method of Testfor Direct Shear Strength of Rock Core Specimen,” U.S. Military RockTesting Handbook, RTH-203-80, available at“http://www.wes.army.mil/SL/MTC/handbook/RT/RTH/203-80.pdf” (lastaccessed on Oct. 1, 2010); and “Standard Method of Test for MultistageTriaxial Strength of Undrained Rock Core Specimens Without Pore PressureMeasurements,” U.S. Military Rock Testing Handbook, available athttp://www.wes.army.mil/SL/MTC/handbook/RT/RTH/204-80.pdf” (lastaccessed on Jun. 25, 2010). One of ordinary skill will recognize thatother methods of testing rock specimens from formations may be used todetermine the physical constants used herein.

“Natural gas” refers to various compositions of raw or treatedhydrocarbon gases. Raw natural gas is primarily comprised of lighthydrocarbons such as methane, ethane, propane, butanes, pentanes,hexanes and impurities like benzene, but may also contain small amountsof non-hydrocarbon impurities, such as nitrogen, hydrogen sulfide,carbon dioxide, and traces of helium, carbonyl sulfide, variousmercaptans, or water. Treated natural gas is primarily comprised ofmethane and ethane, but may also contain small percentages of heavierhydrocarbons, such as propane, butanes, and pentanes, as well as smallpercentages of nitrogen and carbon dioxide.

An “orthotropic” material is one that has three symmetry planes and nineindependent elastic constants if a strain-energy function exists. If theprincipal axes of strain coincide with the symmetry axes, then so do theprincipal axes of stress.

“Overburden” refers to the subsurface formation overlying the formationcontaining one or more hydrocarbon-bearing zones (the reservoirs). Forexample, overburden may include rock, shale, mudstone, or wet/tightcarbonate (such as an impermeable carbonate without hydrocarbons). Anoverburden may include a hydrocarbon-containing layer that is relativelyimpermeable. In some cases, the overburden may be permeable.

“Overburden stress” refers to the load per unit area or stress overlyingan area or point of interest in the subsurface from the weight of theoverlying sediments and fluids. In one or more embodiments, the“overburden stress” is the load per unit area or stress overlying thehydrocarbon-bearing zone that is being conditioned or produced accordingto the embodiments described. In general, the magnitude of theoverburden stress may primarily depend on two factors: 1) thecomposition of the overlying sediments and fluids, and 2) the depth ofthe subsurface area or formation. Similarly, underburden refers to thesubsurface formation underneath the formation containing one or morehydrocarbon-bearing zones (reservoirs).

“Permeability” is the capacity of a formation to transmit fluids throughthe interconnected pore spaces of the rock. Permeability may be measuredusing Darcy's Law: Q=(k ΔP A)/(μL), where Q=flow rate (cm³/s),ΔP=pressure drop (atm) across a cylinder having a length L (cm) and across-sectional area A (cm²), μ=fluid viscosity (cp), and k=permeability(Darcy). The customary unit of measurement for permeability is themillidarcy. The term “relatively permeable” is defined, with respect toformations or portions thereof, as an average permeability of 10millidarcy or more (for example, 10 or 100 millidarcy). The term“relatively low permeability” is defined, with respect to formations orportions thereof, as an average permeability of less than about 10millidarcy. An impermeable layer generally has a permeability of lessthan about 0.1 millidarcy. By these definitions, shale may be consideredimpermeable, for example, ranging from about 0.1 millidarcy (100microdarcy) to as low as 0.00001 millidarcy (10 nanodarcy).

“Porosity” is defined as the ratio of the volume of pore space to thetotal bulk volume of the material expressed in percent. Although thereoften is an apparent close relationship between porosity andpermeability, because a highly porous formation may be highly permeable,there is no real relationship between the two; a formation with a highpercentage of porosity may be very impermeable because of a lack ofcommunication between the individual pores, capillary size of the porespace or the morphology of structures constituting the pore space. Forexample, the diatomite in one exemplary rock type found in formations,Belridge, has very high porosity, at about 60%, but the permeability isvery low, for example, less than about 0.1 millidarcy.

The “Poisson's ratio” of a rock sample from a formation is the ratio ofa unit of lateral contraction to a unit of longitudinal extension fortension. It is a dimensionless elastic property of the material and isusually denoted by the Greek alphabet, and is given by:

$v = {\frac{\lambda}{2\left( {\lambda + \mu} \right)}.}$

“Pressure” refers to a force acting on a unit area. Pressure is usuallyshown as pounds per square inch (psi). “Atmospheric pressure” refers tothe local pressure of the air. Local atmospheric pressure is assumed tobe 14.7 psia, the standard atmospheric pressure at sea level. “Absolutepressure” (psia) refers to the sum of the atmospheric pressure plus thegauge pressure (psig). “Gauge pressure” (psig) refers to the pressuremeasured by a gauge, which indicates only the pressure exceeding thelocal atmospheric pressure (a gauge pressure of 0 psig corresponds to anabsolute pressure of 14.7 psia).

As previously mentioned, a “reservoir” or “hydrocarbon reservoir” isdefined as a pay zone or production interval (for example, a hydrocarbonbearing subterranean formation) that includes sandstone, limestone,chalk, coal, and some types of shale. Pay zones can vary in thicknessfrom less than one foot (0.3048 m) to hundreds of feet (hundreds of m).The permeability of the reservoir formation provides the potential forproduction.

“Reservoir properties” and “Reservoir property values” are defined asquantities representing physical attributes of rocks containingreservoir fluids. The term “reservoir properties” as used in thisapplication includes both measurable and descriptive attributes.Examples of measurable reservoir property values include impedance toP-waves, impedance to S-waves, porosity, permeability, water saturation,and fracture density. Examples of descriptive reservoir property valuesinclude facies, lithology (for example, sandstone or carbonate), andenvironment-of-deposition (EOD). Reservoir properties may be populatedinto a reservoir framework of computational cells to generate areservoir model.

A “rock physics model” relates petrophysical and production-relatedproperties of a formation (or its constituents) to the bulk elasticproperties of the formation. Examples of petrophysical andproduction-related properties may include, but are not limited to,porosity, pore geometry, pore connectivity volume of shale or clay,estimated overburden stress or related data, pore pressure, fluid typeand content, clay content, mineralogy, temperature, and anisotropy andexamples of bulk elastic properties may include, but are not limited to,P-impedance and S-impedance. A rock physics model may provide valuesthat may be used as a velocity model for a seismic survey.

“Shale” is a fine-grained clastic sedimentary rock that may be found informations, and may often have a mean grain size of less than 0.0625 mm.Shale typically includes laminated and fissile siltstones andclaystones. These materials may be formed from clays, quartz, and otherminerals that are found in fine-grained rocks. Non-limiting examples ofshales include Barnett, Fayetteville, and Woodford in North America.Shale has low matrix permeability, so gas production in commercialquantities requires fractures to provide permeability. Shale gasreservoirs may be hydraulically fractured to create extensive artificialfracture networks around wellbores. Horizontal drilling is often usedwith shale gas wells.

“Stimulated Rock Volume” (SRV) describes a relatively large formationvolume that has experienced increased permeability and associatedhydrocarbon production potential through the use of changed in-situstress (either applied or reduced stress) and strain techniques, such asbut not limited to hydraulic fracturing or other related reservoirstimulation or stressing techniques. In one potential SRV scenario, anetwork of hydraulic fractures could be in communication with fracturesthat naturally occur in the formation so that the formation volumeoutside of one specific hydraulic fracture experiences improvedreservoir properties.

“Strain” is the fractional change in dimension or volume of thedeformation induced in the material by applying stress. Stain is usuallydenoted by the Greek alphabet The nine components which fully define thestrain at a given point are expressed as _(ij), where i, j, each takethe values 1, 2, 3.

“Stress” is the application of force to a material, such as a through ahydraulic fluid used to fracture a formation. Stress can be measured asforce per unit area. Thus, applying a longitudinal force f to across-sectional area S of a strength member yields a stress which isgiven by f/S. The force f could be compressional, leading tolongitudinally compressing the strength member, or tensional, leading tolongitudinally extending the strength member. Stress is usually denotedby the Greek alphabet {tilde over ( )} The nine components which fullydefine the stress state at a given point are expressed as _(ij), wherei, j, each take the values 1, 2, 3.

“Substantial” when used in reference to a quantity or amount of amaterial, or a specific characteristic thereof, refers to an amount thatis sufficient to provide an effect that the material or characteristicwas intended to provide. The exact degree of deviation allowable may insome cases depend on the specific context.

“Thermal fractures” are fractures created in a formation caused byexpansion or contraction of a portion of the formation or fluids withinthe formation. The expansion or contraction may be caused by changingthe temperature of the formation or fluids within the formation. Thechange in temperature may change the pressure of fluids within theformation, resulting in the fracturing. Thermal fractures may propagateinto or form in neighboring regions significantly cooler than the heatedzone.

“Tight oil” is used to reference formations with relatively low matrixpermeability, porosity, or both, where liquid hydrocarbon productionpotential exists. In these formations, liquid hydrocarbon production mayalso include natural gas condensate.

“Underburden” refers to the subsurface formation below or fartherdownhole than a formation containing one or more hydrocarbon-bearingzones, e.g., a hydrocarbon reservoir. For example, underburden mayinclude rock, shale, mudstone, or a wet/tight carbonate, such as animpermeable carbonate without hydrocarbons. An underburden may include ahydrocarbon-containing layer that is relatively impermeable. In somecases, the underburden may be permeable. The underburden may be aformation that is distinct from the hydrocarbon bearing formation or maybe a selected fraction within a common formation shared between theunderburden portion and the hydrocarbon bearing portion. Intermediatelayers may also reside between the underburden layer and the hydrocarbonbearing zone.

The “Young's modulus” of a rock sample from a formation is the stiffnessof the rock sample, defined as the amount of axial load (or stress)sufficient to make the rock sample undergo a unit amount of deformation(or strain) in the direction of load application, when deformed withinits elastic limit. The higher the Young's modulus, the more stress isrequired to deform it. It is an elastic property of the material and isusually denoted by the English alphabet E having units the same as thatof stress, and is given by:

$E = {\frac{\mu \left( {{3\lambda} + {2\mu}} \right)}{\lambda + \mu}.}$

Overview

Embodiments of the present techniques provide well completions andmethods for stimulation of hydrocarbon bearing subterranean formations,or portions thereof, on a large scale, up to stimulating an entireformation at once. The methods include fracturing a subterraneanformation by applying stress in a zone proximate to the subterraneanformation to indirectly translate a mechanical stress to thesubterranean formation and affect a permeability increase within thesubterranean formation. In embodiments, the desired permeabilityincrease is effected by creation of a fracture field in the subterraneanformation, such as by delamination fracturing during uplifting,down-folding or other affected movement of the subterranean formation.The desired permeability may also be the result of other types offracturing, but it is noted that for simplification purposes, all suchfracturing and displacements may be referred to herein generally asfracturing.

The techniques may be used with any type of hydrocarbon bearingsubterranean formation, such as oil, gas, or mixed reservoirs and mayalso be used to fracture other types of formations, such as formationsused for the production of geothermal energy. In exemplary embodiments,the techniques can be used to enhance production of natural gas fromunconventional, e.g., low permeability, gas reservoirs.

In embodiments described herein a single wellbore may be used to reachboth the zone proximate and the hydrocarbon bearing subterraneanformation, or separate wellbores may be used for access to each of thezone proximate and the subterranean formation. Similarly, a set of wellsmay be used for application of the principles and methods disclosed andprovided herein, such as in a field-wide plan that utilizes numerouswellbores to effect the techniques provided herein. The inventivemethods and systems provided herein may also be applied using any of avariety of wellbore configurations, such as substantially verticalwells, horizontal wells, multi-branch wells, deviated wellbores, andcombinations thereof. Well completions that may be used in embodimentsare discussed further with respect to FIGS. 11 and 12.

In embodiments, the stress on the zone proximate to the target formationmay be applied by increasing a volume of the zone proximate. Forexample, a volumetric increase may be created in the zone proximate byintroducing a stress-inducing force into the zone proximate, such as viahydraulic fluid, explosively generated gases or pressure, thermalexpansion, proppant or cuttings introduction, or other means ofaffecting such forces. The introduced force may be residual and longlasting or maintained such as via hydraulic fluid introduction, or shortin duration such as via explosives. Either such action may introduceresidual volume increases, even though at least a portion of the volumeincrease may be lost when the force is removed. The action in the zoneproximate is then translated or transferred into the objectiveformation, the subterranean formation, whereby a fracture field iscreated within the subterranean formation.

In embodiments, the stress on the zone proximate to the target formationmay be applied by decreasing a volume of the zone proximate. Thedecrease in the volume of the zone proximate may effect a reduction instructural support within the zone proximate. This reduction instructural support translates into a corresponding reduction instability of the hydrocarbon bearing subterranean formation, resultingin creation of a fracture field within the subterranean formation.Examples of effecting a stress reduction in the zone proximate mayinclude freshwater dissolution of salt from a zone proximate, productionof water or other fluids from a zone proximate to reduce structuralsupport in the subterranean formation, chemical dissolution of the rockmaterial within the zone proximate, physical removal of portion of thezone proximate, such as via a network of relatively large orunder-reamed wellbores within the zone proximate, and similar actions ortreatments to reduce structural strength of the zone proximate withrespect to the in-situ, pre-treatment, or pre-action strength.

Further, the changes in the stress of the zone proximate do not have toinvolve a volumetric change. The methods described herein may includeany number of other techniques that alter the geomechanical stresses ofa formation, including external or internal stresses, by dislocation,displacement, strain changes, or fracturing of a zone proximate orsubterranean formation, without substantial volumetric change therein.Although a volumetric change is not necessarily involved, the stress canstill be communicated from the zone proximate to the targetedsubterranean formation. The techniques described herein generallyinclude treating a zone proximate to a target formation to effect astress change in the zone proximate, which will effect a permeabilityincrease in the target formation.

Further, the application of the stress, e.g., through volumetricchanges, does not have to be performed as a single event. In someembodiments, application and removal of the stress and strain on thezone proximate may be cycled to cause subsequent rubblization andfracturing within the subterranean formation. The increased rubblizationat fracture surfaces can lead to further improvements in permeabilitywithin the targeted formation.

The stress applied to the targeted formation can cause delamination oflayers and other forms of non-hydraulic fracturing, leading to theformation of cracks over a broad area. The cracks or fractures mayresult from a residual or “hysteresis” displacement of the formationcomponents due to the strain displacement that remains, both while thestress is applied and after the stress is relaxed. The hysteresis effectresults from the failure of the crack or fracture to heal completely, inthe event further fracturing happens and/or the applied stress isreduced. Thereby, the permeability may be at least somewhat permanentlyimproved. Ideally, the stress applied to the target formation createssome residual permeability in at least a portion of the targetedsubterranean formation. The treatment duration may range from seconds,such as if explosives are used, to a period of months, such as if wastetailings are used to fracture and prop open the fractures in the zoneproximate formation.

At the delaminated fractures, the formation surfaces or rock stratawithin the formation can be destroyed, forming a rubble layer orinterface between the surfaces. Further, the formation surfaces can beoffset from their original position, forming open apertures between thesurfaces. If the volume changes in the proximate formation are repeated,the rubblization may be increased, forming channels through whichnatural gas, other hydrocarbons, or heated water, may be harvested. Theuse of an applied mechanical stress may be considered counterintuitive,since such stresses would normally tend to close fractures or cleats,leading to lower production. However, in exemplary embodiments, theapplication of stress may provide increased permeability and productionrates, due to delamination along weak layers and rubblization within thetarget reservoir, as mentioned above and discussed in further detailbelow.

Although shown as be substantially parallel or coplanar with respect toeach other in the figures to follow, the zone proximate and thehydrocarbon bearing subterranean formation may be situated innon-parallel planes. The zone proximate and hydrocarbon bearingsubterranean formation may also be oriented substantially horizontal,vertical, deviated, folded, originally arched, faulted, or irregularlypositioned with respect to the wellbore and each other. Each maycomprise a single geologic formation, zone, lens, or structure, ormultiple formations, zones, lenses, or structures.

As discussed herein, embodiments of the present techniques can increasewell productivity, lessen environmental impact, enhance well integrityand reliability, and improve well utilization and hydrocarbon recoveryby inducing delamination fractures (D-Fracs) within a hydrocarbonbearing subterranean formation. Further, production rates and therecovery factor may be enhanced by cyclic “rubblization” over the fullformation thickness. In contrast to hydraulic fracturing, which isgenerally halted by geological drainage boundaries, such as faults andpinchouts, delamination fractures may extend beyond geologic drainageboundaries, thereby reducing the number of wells and associatedenvironmental footprint required for economic development. For example,the delamination may cover an area of about nine times the area of thevolumetric expansion when the strength of the activated bedding planeinterfaces are sufficiently low.

FIG. 1 is a diagram of a hydraulic fracturing process 100. Thetraditional method of fracture stimulation utilizes “hydraulic” pressurepumping and is a proven technology that has been used since the 1940s inmore than 1 million wells in the United States to help produce oil andnatural gas. In typical oilfield operations, the technology involvespumping a water-sand mixture into subterranean layers where the oil orgas is trapped. The pressure of the water creates tiny fissures orfractures in the rock. After pumping is finished the sand props open thefractures, allowing the oil or gas to escape from the hydrocarbonbearing formation and flow to a wellbore.

For example, a well 102 may be drilled through an overburden 104 to ahydrocarbon bearing subterranean formation 106. Although the well 102may penetrate through the hydrocarbon bearing subterranean formation 106and into the underburden 108, perforations 110 in the well 102 candirect fluids to and from the hydrocarbon bearing subterranean formation106. The hydraulic fracturing process 100 may utilize an extensiveamount of equipment at the well site. This equipment may include fluidstorage tanks 112 to hold the fracturing fluid, and blenders 114 toblend the fracturing fluid with other materials, such as proppant 116and other chemical additives, forming a low pressure slurry. The lowpressure slurry 118 may be run through a treater manifold 120, which mayuse pumps 122 to adjust flow rates, pressures, and the like, creating ahigh pressure slurry 124, which can be pumped down the well 102 tofracture the rocks in the hydrocarbon bearing subterranean formation106. A mobile command center 126 may be used to control the fracturingprocess.

The goal of hydraulic fracture stimulation is to create ahighly-conductive fracture zone 128 by engineering subsurface stressconditions to induce pressure parting of the formation in thehydrocarbon bearing subterranean formation 106. This is generallyperformed by injecting fluids with a high permeability proppant 116,such as sand, into the hydrocarbon bearing subterranean formation 106 toovercome “in-situ” stresses and hydraulically-fracture the reservoirrock. A number of liquids may be sequentially injected to perform thefracturing. Generally, the liquids will be sequentially increased inviscosity until a highest viscosity fluid is used. Any number of otherpumping orders and system may be used in embodiments, for example, whenfracturing zones that are proximate to the hydrocarbon bearingsubterranean formation.

The fracture zone 128 may be considered a network or “cloud” offractures generally radiating out from the well 102. Depending on thedepth of the hydrocarbon bearing subterranean formation 106, thefractures may often be predominately perpendicular to the beddingplanes, e.g., vertical within the subsurface.

After the fracturing process 100 is completed, the treating fluids areflowed back to minimize formation damage. For example, contact with thefracturing fluids may result in imbibement of the fluids by pores in thehydrocarbon bearing subterranean formation 106, which may actually lowerthe productivity of the reservoir. Further, a carefully controlledflowback may ensure proper fracture closure, trapping the proppant 116in the fractures and holding them open. The fluids may also be flushedto remove the materials, for example, with a solvent, acid, or othermaterial that can dissolve or break down residual traces of thefracturing fluids.

Stimulation is generally effective at near-well scale, for example, inwhich the fracture dimensions are in the 100s of feet. Treating andproduction are often conducted in the same interval, e.g., the portionof the hydrocarbon bearing subterranean formation 106 reached by thewell 102. The fracturing process 100 may use significant amounts offreshwater and proppant materials. The orientation of the fractures iscontrolled by the local stresses in the hydrocarbon bearing subterraneanformation 106 as discussed further with respect to FIG. 2.

FIG. 2 is a drawing of a local stress state 200 for an element 202 in ahydrocarbon bearing subterranean formation. The state of stress in theearth is defined by the mass of the overburden, the pressure in thepores of the rock, the tectonic stresses governing boundary conditions,and the basic mechanical properties of the rock, such as Young's modulusor stiffness. The in-situ earth stresses determine the predominantorientation of hydraulic fractures. The presence of natural fractures,the configuration of the completion itself, and the characteristics ofthe treating fluids may alter the earth stresses near the well andthereby influence growth of hydraulic fractures for a relatively shortdistance away from the well.

The earth stresses can be divided into three principal stresses whereσ_(v) is the vertical stress in this drawing, σ^(H) _(max) is themaximum horizontal stress, and σ^(h) _(min) is the minimum horizontalstress. These stresses are normally compressive and vary in magnitudethroughout the reservoir, particularly in the vertical direction andfrom layer to layer. The vertical stress σ_(v), is typically the mostcompressive stress, i.e., σ_(v)>σ^(H) _(max)>σ^(h) _(min). However,depending on geologic conditions, the vertical stress could be lesscompressive than the maximum horizontal stress, σ^(H) _(max), or thanthe minimum horizontal stress, σ^(h) _(min).

Fractures in a horizontal direction, e.g., perpendicular to a verticallydrilled well or parallel to a horizontally drilled well, may be moreeffective at conducting hydrocarbons back to the well for production. Indeeper wells, the higher vertical stress from the overburden may oftenforce fractures to be predominately vertical, e.g., perpendicular to ahorizontally drilled wellbore.

However, other stress conditions may exist in formations. These stressconditions may contribute to the tendency for horizontal or verticalfractures to form. For example, depending on geologic conditions, thevertical stress could be substantially equivalent to the orthogonallateral stresses. In this condition, termed lithostatic, the directionof a fracture may be controlled by any stress perturbations that takeplace in the formation. One such perturbation is the wellbore itself,which may favor the formation of vertical fractures. Anotherperturbation would be the creation of a notch in the formation, asdiscussed with respect to FIG. 11. The notch may favor the creation ofhorizontal fractures in the formation.

In another condition, the formation may be formed from a rock that isorthotropic. In this case, the rock itself is formed along planar layersthat favor the formation of fractures along the planes. If the planesare parallel to the surface, the formation will have an increasedtendency to form horizontal fractures, even under high vertical stress.As another example, a formation may be overpressured, in which theformation has a high pore pressure. Under this condition, the high porepressure may have a tendency to offset a high vertical stress, allowingthe fracturing to be controlled by the addition of stress perturbationsin the formation. Generally, as the pressure in the hydrocarbon bearingsubterranean formation drops, for example, during production, furtherfracturing may be horizontal due to reorientation of the stresses. Thisis discussed in further detail with respect to FIG. 9. The stresses mayalso be adjusted to favor the growth of horizontal fractures, asdiscussed with respect to FIGS. 9-11.

FIG. 3 is a drawing of a first mode (mode 1) 300 of fracture formation,commonly resulting from a standard hydraulic fracturing process.Fractures generally propagate in one or more of three primary modes asdiscussed with respect to FIGS. 3 and 7. While, each mode is capable ofpropagating a fracture, standard hydraulic fracture stimulationpredominantly utilizes mode 1 300, resulting from “direct” fluidpressure parting of the formation. In mode 1 300, the pressure of thehydraulic fracturing fluid either creates fractures or advancespre-existing fractures. The fractures are propagated by tensile breakingof the rock of the formation at the crack tip.

As noted herein, the fractures may often be nearly vertical andapproximately perpendicular to bedding planes. At shallow depths, thefractures produced may be horizontal, in which case they likely will beparallel to bedding planes. In standard hydraulic fracturing, thehydraulic pressure and fluids directly contact the formation beingfractured or treated. Application of the traditional hydraulicfracturing method to unconventional hydrocarbon resources, such as tightgas or shale gas reservoirs, requires both large numbers of wells andlarge numbers of fracture treatments in each well. These requirementsare largely driven by the relatively small “effective” area that iscreated during the hydraulic fracturing process due to inherentlimitations in the treating fluids, proppants, reservoir stratigraphy,and in-situ stresses. In embodiments of the present techniques, a newfracturing concept can be used to achieve massive fracture stimulationof wells, particularly for unconventional hydrocarbon resources. Inthese embodiments, a volumetric increase in a layer adjacent to thehydrocarbon bearing subterranean formation can be used to place a stresson the reservoir, leading to fracturing in the reservoir.

FIG. 4 is an exemplified drawing of a well treatment system such as ahydraulic fracturing system 400, wherein a zone 402 below a hydrocarbonbearing subterranean formation 404 is subjected to a volumetricexpansion 406, which can place stress on the hydrocarbon bearingsubterranean formation 404 leading to fracturing. The techniques are notlimited to a hydrocarbon bearing subterranean formation 404, but may beused in any number of situations where fracturing a formation layerwould be useful, such as in the production of geothermal energy. In thehydraulic fracturing system 400, all like units are as discussed withrespect to FIG. 1. In this embodiment, the drilling and productionwastes from the field may be used for the hydraulic fracturing of thezone 402, lowering the requirements for freshwater over standardhydraulic fracturing. Further, the drilling cuttings may be used toprovide a proppant to maintain the fractures open in the zone 402. Thepresent techniques are not limited to hydraulic fracturing of the zone402. In embodiments, thermal expansion may be used to create thevolumetric expansion 406. Further, a pressurized liquid may be used tocause the volumetric expansion 406 of the zone 402 without fracturing.The volumetric expansion 406 may be cycled by various techniques, suchas successive thermal heating and cooling cycles, or successive fluidinjections and removal cycles.

In other embodiments, a volumetric contraction may be used in place ofthe volumetric expansion 406. For example, chemical treatment may beapplied in the zone 402 to create an area of cavitation around the well102, such as by using an acid to remove a portion of the zone 402. Insome embodiments, the volumetric contraction may be provided throughproduction of fluids from non-hydrocarbon productive zone 402 to createsubsidence in both the non-hydrocarbon-bearing zone and in the adjacenthydrocarbon bearing subterranean formation 404. Further, a separateborehole could be drilled in the zone 402 to induce the volumetriccontraction. The effects of volumetric contraction may be enhanced byalternately injecting and then producing fluid in successive cycles, forexample, over hours, days, weeks, months, or even years.

In some embodiments, the formation layers of interest are mechanicallydamaged or “delaminated,” for example, by arching, or bending flexure,of the hydrocarbon bearing subterranean formation 404. The method usedto treat the hydrocarbon bearing subterranean formation 404 would needto create a stress state sufficient to impose delamination fracturingalong preferred layers of interest. This may occur from dilatingformations in the zone 402 from below, creating an uplift in thehydrocarbon bearing subterranean formation 404. The delaminationfractures may be created without pressurizing the fracture surfaces ofthe hydrocarbon bearing subterranean formation 404 with treating fluids.As stimulation fluids do not need to contact the surfaces of theformation, the hydrocarbon bearing subterranean formation 404 may not bedamaged by imbibement of the treating fluids. The stimulation may beeffective at reservoir scale, i.e., the fracture dimensions may be onthe order of 1000s of feet. Further, the treating and the production maybe conducted in different intervals, using the same or separate wells.

FIG. 5 is a block diagram of a method 500 for stimulation of ahydrocarbon bearing subterranean formation by treating a formationoutside of the reservoir. The method 500 begins at block 502, with thedrilling and completing of a well to the treatment interval. Thetreatment interval may be a formation under the hydrocarbon bearingsubterranean formation, as generally discussed with respect to FIG. 4.In other embodiments, the treatment interval may be beside or above thehydrocarbon bearing subterranean formation, for example, if thehydrocarbon bearing subterranean formation is in a deviated formation.At block 504, the treatment interval may be treated, such as by achemical, thermal, physical, biological, and/or other treatment. Forexample, fracturing fluids may be injected into the treatment interval.The fracturing fluids may or may not include solids for proppants, suchas crushed drilling cuttings from wells. In some embodiments, thetreatment may be performed by successively cycling the volume of thetreatment interval to cause rubblization of the hydrocarbon bearingsubterranean formation. The treatment may be performed by increasing ordecreasing underburden support and/or pressure and thereafter providingan expansive or contracting force such as pressure or a heat source intothe treatment interval to cause inflation of the treatment interval suchas by thermal expansion. Such deflation and inflation may be cyclicallyperformed.

At block 506, a production well is completed to the reservoir to producehydrocarbons. The production well may be drilled after stimulation fromthe treating well, thereby reducing the potential for subsequent wellintegrity or reliability issues. In embodiments, the production well maybe the same as the treatment well, for example, by creating perforationsin the well at the interval of the hydrocarbon bearing subterraneanformation, or by drilling production wells from the treatment well.Various well configurations may be used, as discussed further withrespect to FIGS. 12 and 13. At block 508, hydrocarbons may be producedfrom the production well.

It will be clear that the techniques described herein are not limited tothe production of hydrocarbons, but may be used in other circumstanceswhere a subterranean formation is fractured to aid in the production offluid. For example, in embodiments, the techniques may be used tofracture a hot dry formation layer for use in geothermal energyproduction. Water or other fluids may then be circulated through thefractures, collected in a production well, and returned to the surfacefor harvesting heat energy. The wells are not limited to theconformations discussed above. In embodiments, various treating, andproducing well patterns and operational schemes may be considered toconcurrently optimize reservoir stimulation, gas production, wastedisposal, and well operability.

FIG. 6 is a more detailed schematic view of a delamination fracturestimulation 600 showing the physics that may lead to delaminationfracturing. A well 602 may be drilled through a hydrocarbon bearingsubterranean formation 604, and into a treatment interval or zone 606below the hydrocarbon bearing subterranean formation 604. The treatmentinterval or zone 606 does not have to be adjacent to the hydrocarbonbearing subterranean formation 604, but may have one or more interveninglayers 608. These layers 608 may lower the chance that a treatmentfluid, if used, will leak into the hydrocarbon bearing subterraneanformation 604. Further, if waste tailing are used as proppants, thelayers 608 may assist in fixing the tailings in place, lowering theprobability that material may migrate into the hydrocarbon bearingsubterranean formation 604 or other locations, such as aquifers.

As the treatment progresses, a volumetric expansion 610 occurs in thetreatment interval or zone 606, which presses upwards on the layers 608,forming an arch or dome 612 in the hydrocarbon bearing subterraneanformation 604. In the embodiment shown, fluids and/or particulate solidsare injected into the treatment interval or zone 606 to dilate, uplift,“arch,” and shear fracture the hydrocarbon bearing subterraneanformation 604. The distance, or vertical distance, between the zone 606and the hydrocarbon bearing subterranean formation 604 may control thesize of the area over which the treatment affects the hydrocarbonbearing subterranean formation 604. A layer that is further from thehydrocarbon bearing subterranean formation 604 may affect a wider area,but with a lower total movement. For example, if a treatment of a zone606 located around 50 m under the hydrocarbon bearing subterraneanformation 604 caused a vertical motion of about 2 cm over a distance ofabout 500 m, treatment of a zone 606 located about 100 m under thehydrocarbon bearing subterranean formation 606, using the samecontraction and/or expansion conditions, may cause a vertical motion ofabout 1 cm over a horizontal distance of about 1000 m.

Further, the arch or dome 612 may have a highest stress region, e.g.,the area in which the fractures form within the hydrocarbon bearingsubterranean formation 604, that is not centered on the injection well602. As the distance between the volumetric expansion 610 and thehydrocarbon bearing subterranean formation 604 increases, so does thedistance between the well 602 and the highest stress point in thehydrocarbon bearing subterranean formation 604. Accordingly, if thehighest stress point in the hydrocarbon bearing subterranean formation604 is sufficiently separated from the well 602, fracturing of thehydrocarbon bearing subterranean formation 604 may be used to couple thefracture field around the highest stress point with the well 602.

In addition to separation distance, the choice of the treatment zone 606may be made on the basis of formation properties, both in the zone 606and in the hydrocarbon bearing subterranean formation 604. A relativelyimpermeable formation may be useful for treatment using hydraulicfracturing techniques, as the zone 606 may have lower leak-off, makingthe treatment more efficient. If waste tailings are going to be used,this may be less of an issue, as the zone 606 may be propped open andexpanded, even after pressure has leaked off. If thermal expansion isgoing to be used, the zone 606 may be selected to have a highercoefficient of thermal expansion than other surrounding zones.

In addition to the properties of the formation within the zone 606, theproperties of the material in the hydrocarbon bearing subterraneanformation 604 may also influence the choice of expansion techniques andlocation. For example, if the hydrocarbon bearing subterranean formation604 is shale, a slow expansion may not open sufficient cracks, as aductile shale may have enough plastic deformation to reseal the cracks.Thus, an explosive deformation may cause a fast enough deformation, suchas on the order of seconds, to shatter the shale without plastic flowresealing the cracks. In this case, the zone 606 may be selected to havea hard rock, such as granite, that can transfer the energy of expansionto the hydrocarbon bearing subterranean formation 604.

A hydrocarbon bearing subterranean formation 604 may often have weakerlayers 614, or even inherent fracture planes 616. The arching can causeshear stress in the hydrocarbon bearing subterranean formation 604,leading to sliding or breaking of the hydrocarbon bearing subterraneanformation 604 along these layers 614 and fracture planes 616, asindicated by the arrows 618, creating delamination fractures 620. Thus,the delamination fracture stimulation 600 can create a highly-conductivemulti-fracture/dual-porosity reservoir system by delaminating formationlayers, parting formation within layers, and rubblizing the formation“in-situ.” The injection operations may also create relative movement ordisplacement between the fracture surfaces along the layers 614 andfracture planes 616 to achieve fracture conductivity, for example, bycreating delamination fractures 620 that contain enhanced permeabilityformation debris. Vertical fractures 622 may also be created during thedelamination process. The control of stresses in the formation may beused to control the direction of the fractures, as discussed withrespect to FIGS. 9 and 10.

In addition to the injection of fluids, embodiments may inducedelamination fractures in the hydrocarbon bearing subterranean formation604 using in-situ techniques, such as thermal heating, explosivedetonations, and the like to enlarge the volume of the treatmentinterval or zone 606 and thereby increase the stresses at the targetformation intervals such that shear-dominated fractures delaminatealong, and possibly normal to, the bedding planes.

The flow conductivity of the delamination fractures may be enhanced bycyclically inflating and deflating the treatment interval or zone 606such that the delaminated formations “rubblize” due to frictionalcontact and relative sliding motion between formation surfaces, creatingan in-situ propped bed of failed formation material. This is discussedfurther with respect to FIG. 8.

In contrast with the direct hydraulic fracture stimulation of ahydrocarbon bearing subterranean formation 604, the delaminationfracture stimulation 600 minimizes direct fluid contact with theformation fracture face, thereby reducing the potential for formationdamage and the need for flowback clean-up. Further, fracture“conductivity” is created in-situ over the full fracture dimensions,thereby enhancing productivity and eliminating the need for transportingproppants. The fractures 620 may also extend beyond geologic drainageboundaries, such as faults, pinchouts and the like, reducing the numberof wells required for economic development. The fracture delaminationmay be created using “waste disposal” products, such as drill cuttings,produced brines, and the like, to enhance volumetric strain, reducingthe need for customized fracturing formulations and large volumes offreshwater. The fracture delamination or other permeability improvementalso may be created with non-aqueous techniques to enhance volumetricstrain, reducing the need for customized fracturing formulations andlarge volumes of freshwater.

In summary, the delamination fracture stimulation 600 is based on threephysical components, including delamination, rubblization, and stresscontrol. The relative importance of each of these components isdependent on the parameters of the particular application, for example,the depths of treatment interval or zone 606 and hydrocarbon bearingsubterranean formation 604, the thicknesses of each interval 604 and606, the formation properties, the pore pressures, the in-situ stressenvironments, and the like. These parameters are discussed in moredetail with respect to FIGS. 7-10.

FIG. 7 is a drawing 700 of two modes of fracture formation that mayparticipate in delamination fracture stimulation as discussed herein.Both of these modes are based on shearing the rock, rather than tensileparting of the rock. An in-plane shear mode 702 develops a fracture 704that is aligned (i.e., in the same two-dimensional plane) with theapplied shear stress 706. The in-plane shear mode 702, also termed modeII, may develop as an arch or bend that distorts a reservoir. Further,the in-plane shear mode 702 may develop horizontal fractures, forexample, as some layers 708 are placed under compressive stress, whileother layers 710 are released from compressive stress. Additional mode1300 “non-hydraulic”tensile fractures also may be incurred from stressarching of the reservoir. Another mode of fracture formation is ananti-plane shear mode 712, also termed mode III. Similarly, theanti-plane shear mode 712 develops a fracture 714 that also is alignedin the same two-dimensional plane with the applied shear stress 716.This mode may also participate in both vertical and horizontal fracturesas adjacent layers are moved in opposite directions. In embodiments,both mode II 702, and mode III 712, or any combinations thereof, maypropagate damage and fractures perpendicular or parallel to beddingplanes through the use of a volumetric increase in layers outside of areservoir interval. The shearing modes may cause material todisaggregate.

FIG. 8 is a drawing of rubblization 800 during shearing 802 at afracture boundary 804. Direct hydraulic fracturing of a reservoirgenerally causes tensile fracturing of reservoir rocks as discussed withrespect mode I shown in FIG. 3. In contrast, the shearing 802 that takesplace in embodiments, as discussed with respect to FIG. 7, can forceformation surfaces to slide against each other at a bedding planeinterface or fracture boundary 804. Frictional engagement of features onthe surfaces may cause the formation to break, leading to the formationof a rubblized layer within or adjacent to the fracture boundary 804.

As mentioned previously, the flow conductivity of delamination fracturesmay be enhanced by cycling the induced flexures such that thedelaminated formations “rubblize” within or adjacent to the fractureboundaries 804 due to frictional contact and relative movement betweenformation surfaces. This process may create a propped bed of failedformation material in-situ. Based on measurements of formation debrisfields created during movements of faults, the thickness of therubblized zone adjacent to the delamination fractures may up to about20% of the cumulative linear or transverse movement of the fracturesurfaces. Although the amount of formation debris created may be lowerwith each subsequent cycle, significant porosity may be created infracture debris zones through the cyclic movement. The failed formationis referred to herein as Cyclic Rubblized Material (“CRM”). CRM resultsin secondary permeability, i.e., dual porosity.

Stress Distribution and Rearrangement

FIG. 9 is a drawing of an azimuthal rotation 900 of fracture planes 902within a formation that may occur as a result of cyclic treatment of theformation. The in-situ earth stresses determine the predominantorientation of hydraulic fractures. At shallow depths, hydraulicfractures generally are horizontal and easily create arching, uplift anddelamination fractures in formation layers above. However, at deeperdepths, hydraulic fractures generally are vertical and the horizontalstresses must be increased to locally re-orient hydraulic fractures.

As discussed above with respect to FIG. 2, the earth stresses can bedivided into three principal stresses. In this case, σ_(v) is thevertical overburden stress and is initially the highest stress in thesystem. Further, σ^(H) _(max) is the maximum horizontal stress, whileσ_(min) is the minimum horizontal stress, where σ_(v)>σ^(H) _(max)>σ^(h)_(min). Specially engineered stress conditions may shift the position ofthe overburden stress to the intermediate (σ^(H) _(max)) or minimumstress (σ^(h) _(min)), especially in regions near the well. For example,the engineering of the stress conditions may be performed bysequentially fracturing and propping the formation, leading to anincrease in horizontal stresses. As the horizontal stresses dominate thevertical stresses, the fracture planes will rotate into the horizontal.

As a result, the axis of each successive fracture plane 902 in a cyclicfracturing process may be slightly shifted or rotated from the lastfracture plane 902, as indicated by an arrow 906. This may continueuntil a final fracture plane 908 may be horizontal. Fracturere-orientation is dependent on the characteristics of the pumpingtreatment (i.e., fluid rheology, temperature, pressure, rate, solidscontent, treatment duration, shut-down schedule), and generally occursinitially about the “azimuth” axis and subsequently about the“inclination” axis until turning horizontal. The technique shown in FIG.9 may be used in any embodiment in which stress is changed in the zoneproximate to the target formation, including a volume expansion of thezone proximate or a volume decrease in the zone expansion.

Although the technique discussed with respect to FIG. 9 will increasestress in the formation and rotate the fracture plane to generatehorizontal fractures, it will take a number of repetitions to performthe rotation. Other techniques may be used to initiate horizontalfracture in a faster timeframe, as discussed with respect to FIGS. 10and 11.

FIG. 10 is a drawing 1000 of a vertical well 1002 passing through areservoir interval 1004 and a treatment interval 1006, in which a notch1008 has been formed in the treatment interval. The notch 1008 is acarved indentation in the treatment interval 1006 that creates a stressincrease at the tip, promoting a horizontal fracture. The notch 1006 canbe created using any number of down hole tools, such as a jet drillingtool. The notch 1006 can also be created using any number of othertechniques, such as a short acid wash to create a wormhole in thetreatment interval 1006. The notching is not limited to the treatmentinterval 1006, but may also be performed in the reservoir interval 1004to promote the growth of a horizontal fracture.

FIG. 11 is a drawing 1100 of the stress distribution in the formationaround the tip of a notch 1102. As can be seen in FIG. 11, the notch1102 creates a high stress region 1104 at the tip, facilitating anorigination of a crack which propagates out in a perpendicular direction1106 from a well 1108. This technique may also be used in thehydrocarbon bearing subterranean formation to enhance the growth ofhorizontal fractures that may be used to couple the well to a fracturefield.

Well Configurations

FIGS. 12(A)-(D) are drawings of a number of well configurations that canbe used in embodiments of the techniques described herein. Like numbereditems are as described with respect to FIG. 4. In FIG. 12 (A), avertical well 1204 is drilled to penetrate both the hydrocarbon bearingsubterranean formation 404 and the zone 402 below the hydrocarbonbearing subterranean formation 404. A treatment may be performed in thezone 402 to create a stressed region 1206, which can create a fracturefield 1208 in the hydrocarbon bearing subterranean formation 404 bydelamination or rubblization. The location of the treatment, e.g., thedistance 1210 between the hydrocarbon bearing subterranean formation 404and the zone 402, can be selected to achieve the desired results. Forexample, a closer distance 1210 may increase an uplift in the immediatevicinity of the well 1204, but may make the total area of the fracturefield 1208 smaller. After treatment, the zone 402 may be plugged orisolated, and the well 1204 may be completed in the hydrocarbon bearingsubterranean formation 404 and used as a producing well. Depending onthe distance 1210 between the zone 402 and the hydrocarbon bearingsubterranean formation 404, fracturing within the bearing subterraneanformation 404 may be used to couple the completed well 1204 to afracture field 1208.

In FIG. 12(B), a well 1212 has a horizontal segment 1214 that is drilledthrough the zone 402 to allow multiple stressed regions 1206, which caninduce a fracture field 1216 over a large area in the hydrocarbonbearing subterranean formation 404. After treatment, the horizontalsegment 1214 of the well 1212 in the zone 402 may be plugged orisolated, and the well 1212 may be completed in the hydrocarbon bearingsubterranean formation 404 to be used as a producing well. Depending onthe offset 1218 between the well 1212 and the first of the stressedregions 1206, the well 1212 may coupled to the fracture field 1216without further fracturing in the hydrocarbon bearing subterraneanformation 404.

FIG. 12(C) is a drawing of a multilateral well 1220 with a lowerhorizontal section 1222 in the zone 402 and an upper horizontal section1224 in the hydrocarbon bearing subterranean formation 404. Themultilateral well 1220 may be used for both stimulation and production.The treatment may first be performed along the horizontal section 1222to create multiple stressed regions 1206. As described herein, themultiple stressed regions 1206 cause the formation of a fracture field1216 in the hydrocarbon bearing subterranean formation 404. Aftertreatment, the lower horizontal section 1222 may be isolated and theupper horizontal section 1224 may be completed and used to producehydrocarbon from the hydrocarbon bearing subterranean formation 404.Multiple horizontal sections may be drilled through the thickness of thezone 402 to improve treatment results.

FIG. 12(D) is a drawing of a well 1226 that has a horizontal section1228, in the hydrocarbon bearing subterranean formation 404, andsubstantially vertical treating arms 1230 extending into the zone 402.In this embodiment, treatment of the zone 402 is performed in thetreating arms 1230, creating stressed regions 1206. As described herein,the multiple stressed regions 1206 cause the formation of a fracturefield 1216 in the hydrocarbon bearing subterranean formation 404. Aftertreatment, the treating arms 1230 may be plugged or isolated, and thewell 1226 may be completed in the hydrocarbon bearing subterraneanformation 404 to produce hydrocarbon as a conventional horizontal well.The design of the well 1226 in FIG. 12(D) allows treatments to beperformed both along the azimuth direction of the horizontal section1228 and in the vertical direction along the treating arms 1230. Thiscan allow multiple stressed regions 1206 to be formed along each of thetreating arms 1230, as well as selecting the separation between thehorizontal section 1228 and the stressed regions 1206.

The efficiencies of the well configurations discussed with respect toFIG. 12 may be further improved. For example, the well configurationsmay be used in branching wells to reach multiple regions of a singlehydrocarbon bearing subterranean formation, as discussed with respect toFIG. 13.

FIGS. 13(A)-(F) are drawings of a series of branched wells that can usethe configurations discussed with respect to FIGS. 12(B) and (D). Likenumbered items are as discussed with respect to FIG. 12. FIGS. 13(A),(B), and (C) illustrate branched arrangements of FIG. 12(B), which maybe useful for accessing larger areas in a zone 402. FIG. 13(A) is a duallateral well 1302 having two branches in the zone 402. FIG. 13(B) is aquadri-lateral well 1304 having four branches in the zone 402. Asindicated by FIGS. 13(A) and (B), the number of branches may only belimited by such practical considerations as the difficulty of drillingmore well branches or the cost of down hole fitting for branchedfracturing operations. Further the branches do not need to be linear andparallel. In the embodiment shown in FIG. 13(C), a pinnate well 1306 hasa number of branches in the zone 402 in a tree arrangement.

FIGS. 13(D), (E), and (F) illustrate branched arrangements of FIG.12(D), which may be useful for accessing larger areas in a zone 402.FIG. 13(D) is a dual lateral well 1308 having two branches in thehydrocarbon bearing subterranean formation 404, each branch havingmultiple treating arms 1230. FIG. 13(E) is a quadri-lateral well 1310having four branches in the hydrocarbon bearing subterranean formation404, each branch having multiple treating arms 1230. As indicated byFIGS. 13(D) and (E), the number of branches may only be limited by suchpractical considerations as the difficulty of drilling more wellbranches or the cost of down hole fitting for branched fracturingoperations. Further the branches do not need to be linear and parallel.In the embodiment shown in FIG. 13(F), a pinnate well 1312 has a numberof branches in a tree arrangement.

Fracturing Techniques

FIG. 14 is a drawing 1400 of a technique that may be useful forincreasing the effects of the treatment of a zone 402 on the hydrocarbonbearing subterranean formation 404. Like numbered items are as describedwith respect to FIG. 4. In the technique, multiple treatment points 1402are created in the zone 402. As the injection technique described maytake a significant amount of time to effect a change in the zone 402,the use of multiple treatment points 1402 may amplify the effects,shortening the treatment time. The treatment points 1402 may befractures, injection locations for poroelastic expansion of the zone402, locations of heat sources for thermal expansion of the zone 402,and the like. Each of the treatment points 1402 may be successively orconcurrently inflated by the pumping of high pressure fluid into thetreatment points 1402. The expansion at multiple treatment points 1402may increase the stress applied to the hydrocarbon bearing subterraneanformation 404, increasing the number or extent of the fractures in afracture field and shortening the treatment time.

Monitoring the Treatment

Monitoring and controlling the treatments described herein may beperformed by a number of techniques. Stimulation treatments often showtheir signatures through earth deformation on the surface or within asubterranean formation, which may be captured by appropriatesurveillance or monitoring methods. By the measured deformation patternand magnitude, it is possible to determine whether a desired treatmenthas been effected. For example, if an axisymmetric deformation patternis detected on the surface, one can conclude that treatment is beingperformed through a horizontal treatment fracture. However, if surfacedeformation shows two peaks separated by a trough, then treatment isbeing performed through a vertical fracture. Modeling efforts may beused to establish a direct correlation between surface or subsurfacedeformation magnitudes and delamination extent in the reservoir for anygiven geology. The correlation, when implemented in a computer-basedsystem and combined with real-time monitoring technology, may be used toprovide on-the-job treatment feedback and results prediction. Potentialsurveillance options include, among others, tiltmeter arrays installedon the surface or downhole inside dedicated wells, microseismicmonitoring, GPS units installed at selected locations on the surface,and InSAR (Interferometric Synthetic Aperture Radar) images of thesurface before and after the treatment.

Tiltmeters are useful devices for monitor the treatment as they canprecisely measure the earth deformation induced by the treatment. Inaddition, they may easily communicate with a computer system so thatreal-time treatment feedback and optimization may be implemented.

Microseismic technology may be used to obtain the locations of theshearing events accompanying the treatment, from which approximate shapeof the treatment may be obtained. Microseismic technology can also beused for real-time monitoring of the treatment, but it cannot accuratelyprovide the size and shape of the treatment.

Both GPS units and InSAR images may be used to measure the surfacedeformation caused by subterranean treatment. Due to the generally lowresolution (>1 mm) of these techniques, they are applicable only if thetreatment volume is extremely large. In addition, real-time monitoringmay be difficult to implement as both GPS and InSAR rely oncommunication with satellites.

Embodiments of the claimed subject matter may include the methods andsystems disclosed in the following lettered paragraphs:

A. A method for fracturing a production formation, including:

-   -   drilling a well into a zone proximate to a production formation;        and    -   increasing a volume of the zone through the well in order to        apply a mechanical stress to the production formation.

B. The method of paragraph A, including:

-   -   isolating a portion of the well that accesses the zone from a        portion of the well that accesses the production formation;    -   completing a portion of the well in the production formation;        and    -   producing hydrocarbons through the well.

C. The method of paragraph A, including:

-   -   drilling a first horizontal branch from the well into the zone        below the production formation;    -   drilling a second horizontal branch from the well into the        production formation;    -   changing the volume of the zone using the first horizontal        branch; and    -   producing hydrocarbons from the production formation using the        second horizontal branch.

D. The method of paragraph A, including:

-   -   drilling a horizontal branch from the well into the zone; and    -   changing the volume of the zone at a plurality of points along        the horizontal branch.

E. The method of paragraph A, including:

-   -   drilling a horizontal branch from the well into the production        formation;    -   drilling a plurality of vertical branches into the zone from the        horizontal branch; and    -   changing the volume of the zone at a point along the vertical        branch.

F. The method of paragraph A, including:

-   -   creating a notch in the zone; and    -   fracturing the zone at the notch to create a horizontal        fracture.

G. The method of paragraph A, wherein increasing the volume includesexpanding the zone by injecting a pressurized fluid without fracturingthe zone.

H. A hydrocarbon production system, including:

-   -   a hydrocarbon reservoir;    -   a zone proximate to the hydrocarbon reservoir;    -   a stimulation well drilled to the zone;    -   a stimulation system configured to create a volumetric change in        the zone through the stimulation well; and    -   a production well drilled to the hydrocarbon reservoir.

I. The hydrocarbon production system of paragraph H, wherein thestimulation well includes a horizontal segment through the zone andopenings at a plurality of locations along the horizontal segment areused to create the volumetric change.

J. The hydrocarbon production system of paragraph H, including avertical well that is drilled to both the hydrocarbon reservoir and thezone, wherein:

-   -   an opening into the zone is used for the volumetric change; and    -   an opening into the hydrocarbon reservoir is used for        production.

K. The hydrocarbon production system of paragraph H, wherein:

-   -   the stimulation well is a first horizontal branch from a        vertical well; and    -   the production well is a second horizontal branch from a        vertical well.

L. The hydrocarbon production system of paragraph H, wherein:

-   -   the production well includes a horizontal branch through the        production formation; and    -   the stimulation well includes a plurality of vertical branches        off of the horizontal branch that reach into the zone.

M. The hydrocarbon production system of paragraph H, wherein:

-   -   the stimulation well includes a plurality of horizontal branches        in the zone; and    -   a plurality of openings along each of the plurality of        horizontal branches are used to create a volumetric change at        each of the plurality of openings.

N. The hydrocarbon production system of paragraph H, wherein:

-   -   the production well includes a plurality of horizontal branches        in the production formation; and    -   the stimulation well includes a plurality of vertical branches        along each of the plurality of horizontal branches, wherein an        opening along each of the plurality of vertical branches is used        to create a volumetric change at the opening.

O. The hydrocarbon production system of paragraph N, wherein theplurality of horizontal branches are arranged in a dual lateral,quadrilateral, multilateral, or pinnate formation.

Still other embodiments of the claimed subject matter may include themethods and systems disclosed in the following numbered paragraphs:

1. A method for fracturing a production formation, including:

-   -   drilling a well into a zone proximate to a production formation;        and    -   increasing a volume of the zone through the well in order to        apply a mechanical stress to the production formation.

2. The method of paragraph 1, wherein the mechanical stress is appliedto only a portion of the production formation so as to create a bendingmotion in the production formation and cause fractures to form throughdelamination.

3. The method of paragraph 1, including:

-   -   isolating a portion of the well that accesses the zone from a        portion of the well that accesses the production formation;    -   completing a portion of the well in the production formation;        and    -   producing hydrocarbons through the well.

4. The method of paragraph 1, further including:

-   -   reversing the volume change; and    -   repeating the volume change for one or more cycles to cause        rubblization along a delamination fracture in the production        formation.

5. The method of paragraph 1, including:

-   -   drilling a first horizontal branch from the well into the zone        below the production formation;    -   drilling a second horizontal branch from the well into the        production formation;    -   changing the volume of the zone using the first horizontal        branch; and    -   producing hydrocarbons from the production formation using the        second horizontal branch.

6. The method of paragraph 1, including:

-   -   drilling a horizontal branch from the well into the zone; and    -   changing the volume of the zone at a plurality of points along        the horizontal branch.

7. The method of paragraph 1, including:

-   -   drilling a horizontal branch from the well into the production        formation;    -   drilling a plurality of vertical branches into the zone from the        horizontal branch; and    -   changing the volume of the zone at a point along the vertical        branch.

8. The method of paragraph 1, including:

-   -   creating a notch in the production formation; and    -   fracturing the production formation at the notch to create a        horizontal fracture.

9. The method of paragraph 1, including:

-   -   creating a notch in the zone; and    -   fracturing the zone at the notch to create a horizontal        fracture.

10. The method of paragraph 1, including monitoring a change in volumeof the zone.

11. The method of paragraph 10, including creating a microseismic map ofthe zone.

12. The method of paragraph 10, including tracking changes in angle at aground surface or in an existing wellbore.

13. The method of paragraph 1, wherein changing the volume includesexpanding the zone by injecting a pressurized fluid without fracturingthe zone.

14. The method of paragraph 1, further including producing a hydrocarbonfrom the production formation.

15. A hydrocarbon production system, including:

-   -   a hydrocarbon reservoir;    -   a zone proximate to the hydrocarbon reservoir;    -   a stimulation well drilled to the zone;    -   a stimulation system configured to create a volumetric change in        the zone through the stimulation well; and    -   a production well drilled to the hydrocarbon reservoir.

16. The hydrocarbon production system of paragraph 15, wherein thestimulation well includes a horizontal segment through the zone andopenings at a plurality of locations along the horizontal segment areused to create the volumetric change.

17. The hydrocarbon production system of paragraph 15, wherein thehydrocarbon reservoir includes a tight gas layer.

18. The hydrocarbon production system of paragraph 15, wherein thehydrocarbon reservoir includes a shale rock, a mudstone rock, asandstone, or any combinations thereof.

19. The hydrocarbon production system of paragraph 15, including avertical well that is drilled to both the hydrocarbon reservoir and thezone, wherein:

-   -   an opening into the zone is used for the volumetric change; and    -   an opening into the hydrocarbon reservoir is used for        production.

20. The hydrocarbon production system of paragraph 15, wherein:

-   -   the stimulation well is a first horizontal branch from a        vertical well; and    -   the production well is a second horizontal branch from a        vertical well.

21. The hydrocarbon production system of paragraph 20, wherein openingsat a plurality of locations along the first horizontal branch are usedto create the volumetric change at each opening.

22. The hydrocarbon production system of paragraph 15, wherein:

-   -   the production well includes a horizontal branch through the        production formation; and    -   the stimulation well includes a plurality of vertical branches        off of the horizontal branch that reach into the zone.

23. The hydrocarbon production system of paragraph 15, wherein:

-   -   the stimulation well includes a plurality of horizontal branches        in the zone; and    -   a plurality of openings along each of the plurality of        horizontal branches are used to create a volumetric change at        each of the plurality of openings.

24. The hydrocarbon production system of paragraph 23, wherein theplurality of horizontal branches are arranged in a dual lateral,quadrilateral, multilateral, or pinnate formation.

25. The hydrocarbon production system of paragraph 15, wherein:

-   -   the production well includes a plurality of horizontal branches        in the production formation; and    -   the stimulation well includes a plurality of vertical branches        along each of the plurality of horizontal branches, wherein an        opening along each of the plurality of vertical branches is used        to create a volumetric change at the opening.

26. The hydrocarbon production system of paragraph 25, wherein theplurality of horizontal branches are arranged in a dual lateral,quadrilateral, multilateral, or pinnate formation.

27. A method for harvesting hydrocarbons from a formation, including:

-   -   drilling a production well in a production interval;    -   drilling a stimulation well in a treatment interval;    -   causing a volumetric change in the treatment interval through        the stimulation well, wherein the volumetric change causes the        formation of a fracture field in the production interval;    -   completing the production well to place the production well in        contact with the fracture field; and    -   harvesting hydrocarbons from the production interval.

28. The method of paragraph 27, including:

-   -   forming a notch in the rock of the production interval from an        opening in the production well; and    -   fracturing the rock of the production interval through the notch        to create a horizontal fracture to the fracture field.

29. The method of paragraph 27, including:

-   -   forming a notch in the rock of the treatment interval from an        opening in the stimulation well; and    -   fracturing the rock of the treatment interval through the notch        to create a horizontal fracture; and    -   causing a volumetric increase in the treatment interval by        pumping a fluid into the horizontal fracture in the rock of the        treatment interval.

While the present techniques may be susceptible to various modificationsand alternative forms, the embodiments discussed above have been shownonly by way of example. However, it should again be understood that thepresent techniques are not intended to be limited to the particularembodiments disclosed herein. Indeed, the present techniques include allalternatives, modifications, and equivalents falling within the truespirit and scope of the appended claims.

What is claimed is:
 1. A method for fracturing a production formation,comprising: drilling a well into a zone proximate to a productionformation; and increasing a volume of the zone through the well in orderto apply a mechanical stress to the production formation.
 2. The methodof claim 1, wherein the mechanical stress is applied to only a portionof the production formation so as to create a bending motion in theproduction formation and cause fractures to form through delamination.3. The method of claim 1, comprising: isolating a portion of the wellthat accesses the zone from a portion of the well that accesses theproduction formation; completing a portion of the well in the productionformation; and producing hydrocarbons through the well.
 4. The method ofclaim 1, further comprising: reversing the volume change; and repeatingthe volume change for one or more cycles to cause rubblization along adelamination fracture in the production formation.
 5. The method ofclaim 1, comprising: drilling a first horizontal branch from the wellinto the zone below the production formation; drilling a secondhorizontal branch from the well into the production formation; changingthe volume of the zone using the first horizontal branch; and producinghydrocarbons from the production formation using the second horizontalbranch.
 6. The method of claim 1, comprising: drilling a horizontalbranch from the well into the zone; and changing the volume of the zoneat a plurality of points along the horizontal branch.
 7. The method ofclaim 1, comprising: drilling a horizontal branch from the well into theproduction formation; drilling a plurality of vertical branches into thezone from the horizontal branch; and changing the volume of the zone ata point along the vertical branch.
 8. The method of claim 1, comprising:creating a notch in the production formation; and fracturing theproduction formation at the notch to create a horizontal fracture. 9.The method of claim 1, comprising: creating a notch in the zone; andfracturing the zone at the notch to create a horizontal fracture. 10.The method of claim 1, comprising monitoring a change in volume of thezone.
 11. The method of claim 10, comprising creating a microseismic mapof the zone.
 12. The method of claim 10, comprising tracking changes inangle at a ground surface or in an existing wellbore.
 13. The method ofclaim 1, wherein changing the volume comprises expanding the zone byinjecting a pressurized fluid without fracturing the zone.
 14. Themethod of claim 1, further comprising producing a hydrocarbon from theproduction formation.
 15. A hydrocarbon production system, comprising: ahydrocarbon reservoir; a zone proximate to the hydrocarbon reservoir; astimulation well drilled to the zone; a stimulation system configured tocreate a volumetric change in the zone through the stimulation well; anda production well drilled to the hydrocarbon reservoir.
 16. Thehydrocarbon production system of claim 15, wherein the stimulation wellcomprises a horizontal segment through the zone and openings at aplurality of locations along the horizontal segment are used to createthe volumetric change.
 17. The hydrocarbon production system of claim15, wherein the hydrocarbon reservoir comprises a tight gas layer. 18.The hydrocarbon production system of claim 15, wherein the hydrocarbonreservoir comprises a shale rock, a mudstone rock, a sandstone, or anycombinations thereof.
 19. The hydrocarbon production system of claim 15,comprising a vertical well that is drilled to both the hydrocarbonreservoir and the zone, wherein: an opening into the zone is used forthe volumetric change; and an opening into the hydrocarbon reservoir isused for production.
 20. The hydrocarbon production system of claim 15,wherein: the stimulation well is a first horizontal branch from avertical well; and the production well is a second horizontal branchfrom a vertical well.
 21. The hydrocarbon production system of claim 20,wherein openings at a plurality of locations along the first horizontalbranch are used to create the volumetric change at each opening.
 22. Thehydrocarbon production system of claim 15, wherein: the production wellcomprises a horizontal branch through the production formation; and thestimulation well comprises a plurality of vertical branches off of thehorizontal branch that reach into the zone.
 23. The hydrocarbonproduction system of claim 15, wherein: the stimulation well comprises aplurality of horizontal branches in the zone; and a plurality ofopenings along each of the plurality of horizontal branches are used tocreate a volumetric change at each of the plurality of openings.
 24. Thehydrocarbon production system of claim 23, wherein the plurality ofhorizontal branches are arranged in a dual lateral, quadrilateral,multilateral, or pinnate formation.
 25. The hydrocarbon productionsystem of claim 15, wherein: the production well comprises a pluralityof horizontal branches in the production formation; and the stimulationwell comprises a plurality of vertical branches along each of theplurality of horizontal branches, wherein an opening along each of theplurality of vertical branches is used to create a volumetric change atthe opening.
 26. The hydrocarbon production system of claim 25, whereinthe plurality of horizontal branches are arranged in a dual lateral,quadrilateral, multilateral, or pinnate formation.
 27. A method forharvesting hydrocarbons from a formation, comprising: drilling aproduction well in a production interval; drilling a stimulation well ina treatment interval; causing a volumetric change in the treatmentinterval through the stimulation well, wherein the volumetric changecauses the formation of a fracture field in the production interval;completing the production well to place the production well in contactwith the fracture field; and harvesting hydrocarbons from the productioninterval.
 28. The method of claim 27, comprising: forming a notch in therock of the production interval from an opening in the production well;and fracturing the rock of the production interval through the notch tocreate a horizontal fracture to the fracture field.
 29. The method ofclaim 27, comprising: forming a notch in the rock of the treatmentinterval from an opening in the stimulation well; and fracturing therock of the treatment interval through the notch to create a horizontalfracture; and causing a volumetric increase in the treatment interval bypumping a fluid into the horizontal fracture in the rock of thetreatment interval.